Spud To Reservoir With CWD / PDC Drill-OutSpud To Reservoir With CWD / PDC Drill Out Technology Using an Automated Drilling RigJohn WingategOperations Support Manager for Casing / Liner Drilling

© 2010 Baker Hughes Incorporated. All Rights Reserved.

Agendag

• Technologies– The rig Nieuwendijk– Casing while Drilling (CwD) bit– PDC drill-out bit

• The project2 E l ti ll– 2 Exploration wells

– Drilling/casing plan• Results

– Nieuwendijk-1– Nieuwendijk-1– Tiendeveen-1

• Conclusions• Lessons

• See SPE 128219

© 2009 Baker Hughes Incorporated. All Rights Reserved.

Semi-Automated Drilling Rigg g

• Straight ‘out of the box’C t i i d

Nieuwendijk

• Containerised• Small footprint• Semi automated pipe handler• Semi-automated pipe handler• Singles rig

– Horizontal set-back• Touch screen driller’s console

– Computerised auto-driller• Casing drive tool

Casing while Drilling Bitg g

Casing sub

Drillable steel alloy crown

Rupture port

Nozzle

PDC cutting structure

Engineered internal

g

Engineered internal profile for drill-out

PDC Drill-Out Bit

• Specialised PDC bit• Two functions:

– Drills out the CwD bit– Drills ahead

• Two sets of cutters( C)– Tungsten carbide (TC)

• Overexposed during drill-out• Drill out the CwD shoe• Protect the standard PDC• Protect the standard PDC

cutters• Wear away in formation

– PDC cutters• Exposed when TC cutters

worn down after drill-out• Engages and drills new

formationformation 6-in. Drill-out bit8 1/2-in. Drill-out bit

The Project

j

© 2010 Baker Hughes Incorporated. All Rights Reserved. 6

Application0m

pp

500m

1,000m

1,500m

2 000m2,000m

12-1/4” x 9-5/8” CwD bit

4 blades, 13mm cutters

8-1/2” PDC drill-out bit

6 blades, 16mm TC & PDC

8-1/2” x 7” CwD bit

4 blades, 13mm cuttersd

6” PDC Drill-out bit

4 blades, 16mm cutters2,500m4 x 14/32nd nozzles

0 to 780m (780m)

6 x 16/32nd nozzles

780 to 2,075m (1,295m)

4 x 14/32nd nozzles4 x 14/32nd nozzles

2,075 to 2,418m (343m)

Spudding Nieuwendijk-1: 12 ¼-in. x 9 5/8-in. CwD Run

Results: 12-1/4 section – drilled with casing g

• 12 1/4-in. hole drilled and cased simultaneously from surface to 780 msimultaneously from surface to 780 m

– 11 m/hr• Planned v actual: 2.6 days v 4.4 days

8 hr NPT– 8 hr NPT– Bit balling– Slow connection times

• Auto driller used to identify balling• Auto-driller used to identify balling threshold

• The hole inclination at section TD was 0.63º0.63

• Casing cemented through the nozzles successfully

12 1/4-in. x 9-5/8-in. CwD bit

Results: Drilling 8-1/2” section g

• Drill-out bit run on a motor12 1/4 in CwD bit drilled out in 1 5 hr• 12 1/4-in. CwD bit drilled out in 1.5 hr

• Drilled from 780 to section TD at 2075 m – 1295 m section length

ROP 7 4 /h– ROP 7.4 m/hr– Offset required six bits: combined

ROP of 7.0 m/hr• Balling prevalent thru run• Balling prevalent thru run

– Auto-driller used to identify balling threshold

• Bit graded 1-1-WT-A-X-I-TD• Bit graded 1-1-WT-A-X-I-TD• No damage to PDC cutters

Results: Running 7” casing g g

• After calling section TD the 7-in. casing run in holehole

• Casing stood up at 1924 m – 151 m high– Depth coincided with a fault– Casing drive tool engagedCasing drive tool engaged– Casing reamed to bottom

• 60 RPM, 0 to 20 klbs WOB, 800 lpm• Casing cemented without issueg• There was a degree of geological uncertainty

– The 8 1/2-in. CwD bit meant there was the capability to drill ahead

– Option was not implemented

8 1/2 x 7-in. CwD bit

Results: Drilling 6” sectiong

• Drilled out 8 1/2-in CwD bit in 13 minDrilled from 2075 to 2418 m• Drilled from 2075 to 2418 m

• Pulled early for a motor failure• The bit was graded1-2-WT-A-X-I-CT-

DTFDTF– The cutting structure was in

excellent condition– Without the DTF bit would haveWithout the DTF, bit would have

drilled to TD• The well was completed with a

standard PDC to 2677 m

Results: Well #2 (Tiendeveen-1)( )

• 17 1/2-in. x 13 3/8-in. CwD drilled from surface– 0 to 492 m– 33 hrs at 15 m/hr

• 12 1/4-in. PDC/drill-out bit – Drilled out the 17 1/2-in. x 13 3/8-in. CwD bit– Drilled from 492 to section TD at 2254 m – 1762 m section length

• 9 5/8-in. casing run on 12 1/4-in. CwD bit• The 8 1/2-in. PDC/drill-out bit drilled out the 12

1/4-in x 9 5/8-in CwD bit1/4 in. x 9 5/8 in. CwD bit– Drilled from 2254 to 2951 m – 697 m section length– Pulled for DTF

C l ti d illi l th f C D d PDC d ill• Cumulative drilling length for CwD and PDC drill-outs was 2951 m

– Longest achieved with this technology worldwide Tiendeveen

© 2009 Baker Hughes Incorporated. All Rights Reserved.

Conclusion - General• Nieuwendijk-1 was successfully

drilledN l i i d i 12 1/4-in. x 9 5/8-in. CwD bit– Newly commissioned semi-automated drilling rig

– CwD and PDC drill-out technology

12 1/4 in. x 9 5/8 in. CwD bit

technology– 90% of the well drilled with this

technology• Completed & suspended insideCompleted & suspended inside

AFE• Included first CwD run in The

Netherlands• Motor failure stopped the entire

well being drilled with CwD / PDC drill-out bits T t l l t f t t• Total cumulate footage on two wells 5369 m

Conclusions - CwD

• Nieuwendijk-1 12 1/4-in. CwD run longest in the Europe using thislongest in the Europe using this system – 780 m

• The time taken to complete the 12 1/4-in. section with CwD was

Tiendeveen

comparable using the same rig and conventional drilling techniques

• The 8 1/2-in. CwD bit ensured the 7 in casing was set at depth7-in. casing was set at depth saving 4.5 days NPT

• The 8 1/2-in. hole may still have been deepened even after casingbeen deepened even after casing had been run

• CwD enabled reduced tool/pipe handling and tripping events

Conclusions - Rigg

• The automated pipe handling system and CwD BHA enabled a safe start to the well

TiendeveenCwD BHA enabled a safe start to the well

• Less demanding than conventional drilling– Lower flow rates– Lower SPP

• Wells drilled using rigs with no set-back facility lend themselves to CwD techniques

– The picking up and lying down of singles– Making up/breaking down of a

conventional BHA– All add additional time to the operation

• 2.1 days for a round trip using conventional drilling BHA

Conclusions – Drill-out PDC

• On both wells CwD bits were drilled out with drill-out PDC bits without incidentwith drill out PDC bits without incident

– 5 drill-outs over the two wells – Less than an hour (average)

• The drill-out feature protected theThe drill out feature protected the primary cutting structure during drill-out

– No damage to blades or PDC cutters • Outperformed conventional bitsp

– The best offset well required six bits to complete a comparable 8 1/2-in. section

– The combined ROP over these six bits was 7.0 m/hr

– 7.4 m/hr achieved in one PDC/drill-o t r nout run

Lessons

• Computerized auto-drillerIdentified balling threshold– Identified balling threshold

– Enabled optimised ROP– Allowed precise ROP staging-up

• CwD bit design recommendations:• CwD bit design recommendations:– Three-bladed configuration – Interchangeable nozzles

Relocate the burst disk– Relocate the burst disk– Increasing cutter size (13 to 16mm)

• Centralizer design recommendations Reduced blade count– Reduced blade count

– Smoother transition to blade OD

Spud To Reservoir With CWD / PDC Drill-OutSpud To Reservoir With CWD / PDC Drill Out Technology Using an Automated Drilling RigJohn WingategOperations Support Manager for Casing / Liner Drilling

© 2010 Baker Hughes Incorporated. All Rights Reserved.